Wellbore Telemetry and Noise Cancelation Systems and Methods for the Same

ABSTRACT

A method of signal processing includes providing at least a first pressure sensor and a second pressure sensor spaced in a drilling system and using an algorithm to separate the downwardly propagating waves from the upwardly propagating waves. In one or more examples, an algorithm may include determining a velocity of pressure signals in a wellbore, time-shifting and stacking pressure signals from at least the first pressure sensor and the second pressure sensor to determine a downwardly propagating noise signal, and subtracting the downwardly propagating noise signal from at least the signal from the first pressure sensor.

RELATED APPLICATION

This application is a divisional of U.S. patent application Ser. No.11/614,444, filed on Dec. 21, 2006.

FIELD OF THE DISCLOSURE

The present disclosure relates to telemetry systems and methods for usein wellbore operations. More particularly, the present disclosurerelates to noise cancellation systems and methods for use with wellboretelemetry systems.

BACKGROUND

Wellbores may be drilled to locate and produce hydrocarbons. Typically,a wellbore is formed by advancing a downhole drilling tool having adrill bit at one end into the ground. As the drilling tool is advanced,drilling mud is pumped from a surface mud pit through a passage orpassages in the drilling tool and out the drill bit. The mud exiting thedrill bit flows back to the surface to be returned to the mud pit andmay be re-circulated through the drilling tool. In this manner, thedrilling mud cools the drilling tool, carries cuttings and other debrisaway from the drilling tool, and deposits the cuttings and other debrisin the mud pit. As is known, in addition to the cooling and cleaningoperations performed by the mud pumped into the wellbore, the mud formsa mudcake that lines the wellbore which, among other functions, reducesfriction between the drill string and subterranean formations.

During drilling operations (i.e., advancement of the downhole drillingtool), communications between the downhole drilling tool and asurface-based processing unit and/or other surface devices may beperformed using a telemetry system. In general, such telemetry systemsenable the conveyance of power, data, commands, and/or any other signalsor information between the downhole drilling tool and the surfacedevices. Thus, the telemetry systems enable, for example, data relatedto the conditions of the wellbore and/or the downhole drilling tool tobe conveyed to the surface devices for further processing, display, etc.and also enable the operations of the downhole drilling tool to becontrolled via commands and/or other information sent from the surfacedevice(s) to the downhole drilling tool.

One known wellbore telemetry system 100 is depicted in FIG. 1. A moredetailed description of such a known system is found in U.S. Pat. No.5,517,464, which is incorporated by reference herein in its entirety.With reference to FIG. 1, a drilling rig 10 includes a drive mechanism12 to provide a driving torque to a drill string 14. The lower end ofthe drill string 14 extends into a wellbore 30 and carries a drill bit16 to drill an underground formation 18. During drilling operations,drilling mud 20 is drawn from a mud pit 22 on a surface 29 via one ormore pumps 24 (e.g., reciprocating pumps). The drilling mud 20 iscirculated through a mud line 26 down through the drill string 14,through the drill bit 16, and back to the surface 29 via an annulus 28between the drill string 14 and the wall of the wellbore 30. Uponreaching the surface 29, the drilling mud 20 is discharged through aline 32 into the mud pit 22 so that rock and/or other well debriscarried in the mud can settle to the bottom of the mud pit 22 before thedrilling mud 20 is recirculated.

As shown in FIG. 1, a downhole measurement while drilling (MWD) tool 34is incorporated in the drill string 14 near the drill bit 16 for theacquisition and transmission of downhole data or information. The MWDtool 34 includes an electronic sensor package 36 and a mud pulse ormudflow wellbore telemetry device 38. The mudflow telemetry device 38can selectively block or partially block the passage of the mud 20through the drill string 14 to cause pressure changes in the mud line26. In other words, the wellbore telemetry device 38 can be used tomodulate the pressure in the mud 20 to transmit data from the sensorpackage 36 to the surface 29. Modulated changes in pressure are detectedby a pressure transducer 40 and a pump piston sensor 42, both of whichare coupled to a processor (not shown). The processor interprets themodulated changes in pressure to reconstruct the data collected and sentby the sensor package 36. The modulation and demodulation of a pressurewave are described in detail in commonly assigned U.S. Pat. No.5,375,098, which is incorporated by reference herein in its entirety.

In addition to the known mud pulse telemetry system 100 depicted in FIG.1, other wellbore telemetry systems may be used to establishcommunication between a downhole tool and a surface unit. Examples ofknown telemetry systems include a wired drill pipe wellbore telemetrysystem as described in U.S. Pat. No. 6,641,434, an electromagneticwellbore telemetry system as described in U.S. Pat. No. 5,624,051, anacoustic wellbore telemetry system as described in published PCT PatentApplication No. WO2004085796, all of which are hereby incorporated byreference herein in their entireties. Further examples using dataconveyance or communication devices (e.g., transceivers coupled totransducers or sensors) have also been used to convey power and/or databetween a downhole tool and a surface unit.

Despite the development and advancement of wellbore telemetry devices inwellbore operations, there remains a need for additional reliability andwellbore telemetry capabilities for wellbore operations. As with othermany other wellbore devices, wellbore telemetry devices sometimes fail.Additionally, the power provided by many known wellbore telemetrydevices may be insufficient to power desired wellbore operations.Attempts have been made to use two different types of mud pulsetelemetry devices in a downhole tool. In particular, each of thedifferent mud pulse telemetry devices is typically positioned in thedownhole tool and communicatively linked to a different, respectivesurface unit. Such wellbore telemetry tools have been run simultaneouslyand non-simultaneously and at different frequencies. Attempts have alsobeen made to develop dual channel downhole wellbore telemetry fortransmitting data streams via communication channels to be interpretedindependently as described in U.S. Pat. No. 6,909,667.

SUMMARY

In accordance with one disclosed example, a method of signal processingthat includes providing at least a first pressure sensor and a secondpressure sensor spaced in a drilling system and using an algorithm toseparate the downwardly propagating waves from the upwardly propagatingwaves. In one or more examples, an algorithm may include determining avelocity of pressure signals in a wellbore, time-shifting and stackingpressure signals from at least the first pressure sensor and the secondpressure sensor to determine a downwardly propagating noise signal, andsubtracting the downwardly propagating noise signal from at least thesignal from the first pressure sensor.

In accordance with another disclosed example, a wellbore communicationsystem that includes a plurality of pressure sensors spaced within adrilling system along a drilling fluid flow path and communicativelycoupled to a surface system and a mud pulse telemetry system positionedwithin a downhole tool.

In accordance with another disclosed example, a method for wellborecommunications that includes obtaining a first corrected pressure signaland a downwardly propagating noise signal from at least a first pressuresensor, computing a cross-correlation function between the firstcorrected pressure signal and the downwardly propagating noise signalfor at least the first pressure sensor, computing the standard deviationof the downwardly propagating noise signal, computing a reflectioncoefficient for the downwardly propagating noise signal, computing thereflected, upwardly propagating noise signal, and subtracting theupwardly propagating noise signal from the first corrected pressuresignal.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view, partially in cross-section, of a knownmeasurement while drilling tool and wellbore telemetry device connectedto a drill string and deployed from a rig into a wellbore.

FIG. 2 is a schematic view, partially in cross-section, of an exampletelemetry system including a downhole tool having multiple mud pulsetelemetry devices.

FIG. 3 is a schematic view, partially in cross-section, of anotherexample telemetry system including a downhole tool having a wired drillpipe wellbore telemetry device.

FIG. 4 is a schematic view, partially in cross-section, of a yet anotherexample telemetry system including a downhole tool having a mud pulsetelemetry device and an electromagnetic wellbore telemetry device.

FIG. 5 is a schematic view, partially in cross-section, of still anotherexample telemetry system including a downhole tool having multipledownhole components and multiple wellbore telemetry devices.

FIG. 6 is a schematic view of an example drill string telemetry systemincluding an array of pressure transducers to separate downwardlypropagating rig noise from upwardly propagating measurement whiledrilling signals.

FIG. 7 is a cross-sectional view of an example sub that may be used toimplement the pressure transducers in the example drill string telemetrysystem of FIG. 6.

FIG. 8 depicts an example manner in which the example drill stringtelemetry system of FIG. 6 may be used to detect downwardly propagatingnoise.

FIG. 9 depicts an example manner in which the example drill stringtelemetry system of FIG. 6 may be used to correct upwardly propagatingmeasurement while drilling signals based on downwardly propagating noisesignals.

FIG. 10 is a flow chart describing the process for correcting thepressure transducer signals for downwardly propagating mud pump noise.

FIG. 11 depicts the reflection of downwardly propagating noise isreflected from a change in the interior cross-sectional area of drillpipe, resulting in upwardly propagating noise.

FIG. 12 is a flow chart describing the process for correcting thepressure transducer signals for upwardly propagating mud pump noise thathas been reflected by an obstacle in the drill string below the pressuretransducer.

FIG. 13 is a representation of a two-dimensional data set infrequency-wavenumber space depicting the two-dimensional Fouriertransform of data obtained in depth and time.

FIG. 14 is a cross-sectional view of another example manner in which oneor more pressure transducers may be disposed within a drill string.

DETAILED DESCRIPTION

Despite advancements in wellbore telemetry systems, there remains a needto provide wellbore telemetry systems capable of providing addedreliability, increased speed or bandwidth, and increased powercapabilities. As set forth in the detailed description below, one ormore example methods and apparatus may enable telemetry systems tooperate at one or more desired frequencies and provide increasedbandwidth. Additionally, one or more example methods and apparatusdescribed below may enable a plurality of different wellbore telemetrydevices to be combined with a variety of one or more downholecomponents, such as formation evaluation tools, to provide flexibilityin performing wellbore operations. Still further, one or more examplemethods and apparatus described below may provide backup wellboretelemetry capability, enable the operation of multiple identical orsubstantially similar wellbore telemetry tools, enable the generation ofcomparative wellbore measurements, enable the activation of multiplewellbore telemetry tools, increase the available bandwidth and/or datatransmission rates for communications between one or more downhole toolsand one or more surface units, and enable adaptation of the wellboretelemetry tools to different and/or varying wellbore conditions.

One or more example methods and apparatus described below may alsoutilize drill string telemetry systems and methods that enable thesignal-to-noise ratios associated with measurement while drillingsignals to be increased. In particular, as described in detail below,one or more pressure sensors or transducers (e.g., an array of pressuretransducers) may be disposed (e.g., spaced apart based on a wavelengthof a MWD signal) in a portion of a drill string that is composed ofwired drill pipe. Pressure signal data collected via the pressuretransducers may then be used in conjunction with one or more signalprocessing techniques to separate, suppress and/or cancel downwardlypropagating rig noise (e.g., mud pump generated noise) from upwardlypropagating MWD signals (e.g., from a MWD pulser), thereby increasingthe signal-to-noise ratio of the MWD signals. In addition, upwardlypropagating noise that results from the reflection of downwardlypropagating noise can also be separated and removed from the MWDsignals.

Certain examples are shown in the above-identified figures and describedin detail below. In describing these examples, like or identicalreference numbers are used to identify common or similar elements. Thefigures are not necessarily to scale and certain features and certainviews of the figures may be shown exaggerated in scale or in schematicfor clarity and/or conciseness.

Referring now to FIG. 2, a mud pulse wellbore telemetry system 200having multiple telemetry devices is shown. In contrast to the knownsystem 100 of FIG. 1, the example wellbore telemetry system 200 includestwo MWD tools 234 a and 234 b, two mud pulse telemetry devices 238 a and238 b, two transducers 240 a and 240 b, and two sensors 242 a and 242 b.Additionally, the MWD tools 234 a and 234 b may communicate with asingle surface computer or unit 202 via the mud pulse telemetry devices238 a and 238 b. As can be seen in the example system 200 of FIG. 2, themud pulse telemetry devices 238 a and 238 b are identical orsubstantially identical, the MWD tools 234 a and 234 b are identical orsubstantially identical, and the devices 238 a and 238 b and the tools234 a and 234 b are positioned within a single downhole tool 201 (i.e.,the same downhole tool).

The surface unit or computer 202 may be implemented using any desiredcombination of hardware and/or software. For example, a personalcomputer platform, workstation platform, etc. may store on a computerreadable medium (e.g., a magnetic or optical hard disk, random accessmemory, etc.) and execute one or more software routines, programs,machine readable code or instructions, etc. to perform the operationsdescribed herein. Additionally or alternatively, the surface unit orcomputer 202 may use dedicated hardware or logic such as, for example,application specific integrated circuits, configured programmable logiccontrollers, discrete logic, analog circuitry, passive electricalcomponents, etc. to perform the functions or operations describedherein.

Still further, while the surface unit 202 is depicted in the example ofFIG. 2 as being relatively proximate to the drilling rig 10, some partof or the entire surface unit 202 may alternatively be locatedrelatively remotely from the rig 10. For example, the surface unit 202may be operationally and/or communicatively coupled to the wellboretelemetry system 200 via any combination of one or more wireless orhardwired communication links (not shown). Such communication links mayinclude communications via a packet switched network (e.g., theInternet), hardwired telephone lines, cellular communication linksand/or other radio frequency based communication links, etc. using anydesired communication protocol.

Returning in detail to FIG. 2, the MWD tools 234 a and 234 b may beimplemented using the same device(s) used to implement the MWD tool 34of FIG. 1. Similarly, the mud pulse telemetry devices 238 a and 238 bmay be implemented using the same device(s) used to implement the mudpulse telemetry device 38 of FIG. 1. An example of a mud pulse telemetrydevice that may be used or otherwise adapted to implement the devices38, 238 a, and 238 b is described in U.S. Pat. No. 5,517,464, which haspreviously been incorporated by reference.

In operation, the example wellbore telemetry system 200 of FIG. 2 usesthe mud pulse telemetry devices 238 a and 238 b to generate signals(e.g., modulated pressure signals) in the mud 20 flowing in the annulus28 of the wellbore 30. These generated signals (e.g., modulated orvarying pressure signals) may be sensed by one or more of the pressuretransducers 240 a and 240 b and/or the pressure sensors 242 a and 242 band analyzed by the surface unit 202 to extract or otherwise obtain dataor other information relating to the operational condition(s) of thedownhole tool 201 (e.g., one or both of the MWD tools 234 a and 234 b),conditions in wellbore 30, and/or any other desired downholeinformation. In this manner, communications may be established betweenthe downhole tool 201 and, thus, between the MWD tools 234 a and 234 b,and the surface unit 202. More generally, such communications betweenthe downhole tool 201 and the surface unit 202 may be established usinguplink and/or downlink systems. Further, while mud pulse telemetrydevices 238 a and 238 b are described in connection with the exampletelemetry system 200 of FIG. 2, other types of wellbore telemetrydevices may be employed instead of or in addition to the mud pulsetelemetry devices 238 a and 238 b. For example, one or more mud sirens,positive pulse mud flow telemetry devices, and/or negative pulse mudflow telemetry devices may be used.

In general, the example wellbore telemetry systems described herein mayuse telemetry devices arranged or positioned in various configurationsrelative to the downhole tool. In the example of FIG. 2, one or both ofthe telemetry devices 238 a and 238 b may be operatively orcommunicatively coupled to the same (i.e., a single) MWD tool (e.g., thetool 234 a or the tool 234 b). Alternatively, each of the telemetrydevices 238 a and 238 b may be operatively or communicatively coupled todifferent respective tools. For example, the telemetry device 238 a maybe communicatively or operatively coupled to the MWD tool 234 a and thetelemetry device 238 b may be communicatively or operatively coupled tothe MWD tool 234 b, as depicted in FIG. 2. As described in greaterdetail below, one or both of the telemetry devices 238 a and 238 b maybe communicatively or operatively coupled to one or more additionaldownhole components.

Turning again to the operation of the example system 200 of FIG. 2, themud pulse telemetry devices 238 a and 238 b may send uplink signals(e.g., varying or modulated pressure signals to be conveyed up alongthrough the drill string 14 to the surface 29) by altering the flow ofmud through the telemetry devices 238 a and 238 b. Such uplink signals(e.g., varying or modulated pressure signals) are sensed or detected bythe pressure transducers 240 a and 240 b and/or the pressure sensors 242a and 242 b. In particular, the uplink signals generated by thetelemetry device 238 a may be detected or sensed by the transducer 240 aand/or the pressure sensor 242 a. Similarly, the uplink signalsgenerated by the telemetry device 238 b may be detected or sensed by thetransducer 240 b and/or the pressure sensor 242 b. The pressuretransducers 240 a and 240 b may be implemented using devices identicalor similar to that used to implement the pressure transducer 40 of FIG.1, and the sensors 242 a and 242 b may be implemented using devicesidentical or similar to that used to implement the sensor 42 of FIG. 1.

FIG. 3 is a schematic view, partially in cross-section, of anotherexample telemetry system 300 including a downhole tool 301 having awired drill pipe wellbore telemetry system or device 348. In contrast tothe known mud pulse telemetry system 100 depicted in FIG. 1, the exampletelemetry system 300 utilizes a mud pulse telemetry device 338 that ishoused in a MWD tool 334 and includes the wired drill pipe telemetrysystem 348.

As shown in FIG. 3, the MWD tool 334 and the mud pulse telemetry device338 may be positioned in the downhole tool 301. The MWD tool 334 may beimplemented using a device that is similar or identical to that used toimplement the MWD tool 34 of the FIG. 1 and/or the MWD tools 234 a and234 b of FIG. 2. Similarly, the mud pulse telemetry device 338 may beimplemented using a device that is similar or identical to that used toimplement the mud pulse telemetry device 38 of FIG. 1 and/or the mudpulse telemetry devices 238 a and 238 b of FIG. 2. Additionally, thesurface unit or computer 302 may be implemented in a manner similar tothe surface unit or computer 202 described in connection with FIG. 2.Thus, the surface unit 302 may be operatively or communicatively coupledto the MWD tool 334 via the mud pulse telemetry device 338 and/or may beoperatively or communicatively coupled to the wired drill pipe telemetrysystem 348 via one or more communication links (not shown). As with theexample system 200 of FIG. 2, the surface unit or computer 302 may beproximate the drilling rig 10 or, alternatively, some or all of thesurface unit or computer 302 may be remotely located relative to thedrilling rig 10.

Turning in detail to the wired drill pipe wellbore telemetry system 348,it can be seen in the example of FIG. 3 that the system 348 extendssubstantially entirely through the drill string 14. An example of awired drill pipe wellbore telemetry system that may be used to implementthe system 348 is described in U.S. Pat. No. 6,641,434, which has beenpreviously incorporated by reference herein. As depicted in FIG. 3, thewired drill pipe wellbore telemetry system 348 includes a plurality orseries of wires 352 positioned in each drill pipe 350 that forms orcomposes the drill string 14. A coupler 354 is positioned at the end ofeach of the drill pipes 350 so that when the pipes 350 are connected,joined, or otherwise coupled, the drill string 14 provides a hardwiredcommunication link extending through the drill string 14. While thewired drill pipe telemetry system 348 is depicted in FIG. 3 as extendingsubstantially entirely through the drill string 14 to the MWD tool 334,the wired drill pipe telemetry system 348 may instead extend onlypartially through the drill string 14.

During operation, either or both of the mud pulse telemetry device 338and the wired drill pipe system 348 may be used to enable communicationsbetween the downhole tool 301 (e.g., the MWD tool 334) and the surfaceunit 302. Depending on the particular operational mode of the rig 10and/or downhole or other environmental conditions, the device 338 or thesystem 348 may be best suited to convey data to the surface unit 302.Alternatively or additionally, both the device 338 and the system 348may be used to convey information between the surface unit 302 and thedownhole tool 301 at the same time. In such a case, the conveyedinformation may concern the same downhole parameter(s) or condition(s)or different parameter(s) or condition(s).

FIG. 4 is a schematic view, partially in cross-section, of a yet anotherexample telemetry system 400 including a downhole tool 401 having a mudpulse telemetry device 438 and an electromagnetic wellbore telemetrydevice 448. Similar to the systems 200 and 300 depicted in FIGS. 2 and3, respectively, the system 400 includes a surface unit or computer 402that can communicate with the downhole tool 401 and/or other downholecomponents and analyze information obtained therefrom. In this manner,the surface unit 402 may be operationally or otherwise coupled to a MWDtool 434 via, for example, the mud pulse telemetry device 438. Stillfurther, as with the other systems 200 and 300, the surface unit 402 maybe proximate the drilling rig 10 as shown, or some or all of the surfaceunit 402 may be remotely located relative to the drilling rig 10 andcommunicatively coupled via, for example, any desired combination ofwireless and hardwired communication links to the system 400.

The mud pulse telemetry device 438 is position in the downhole tool 401and may be implemented using the same device or a device similar to thedevice used to implement the device 38 of FIG. 1, the devices 238 a and238 b of FIG. 2, and/or the device 338 of FIG. 3. Also, the MWD tool 434is positioned in the downhole tool 401 and may be implemented using thesame device or a device similar to the device used to implement thedevice(s) used to implement the tools 234 a and 234 b of FIG. 2, and/or334 of FIG. 3.

The electromagnetic wellbore telemetry system 448 includes a downholetransceiver 454 and a surface transceiver 452. An example of anelectromagnetic wellbore telemetry system that may be used to implementthe system 448 of FIG. 4 is described in U.S. Pat. No. 5,624,051,previously incorporated by reference herein. As depicted in the exampleof FIG. 4, the electromagnetic wellbore telemetry system 448 is alsoprovided with a gap collar 450, which is position in the downhole tool401 to enhance the electromagnetic signals conveyed between thetransceivers 452 and 454. An example of a gap collar that may be used toimplement the collar 450 is described in U.S. Pat. No. 5,396,232.

While the example systems depicted in FIGS. 2-4 include certaincombinations of mud pulse telemetry, wired drill pipe telemetry, andelectromagnetic telemetry systems, other combinations of such systemsmay be employed to achieve the same or similar results. For example, awellbore telemetry system using a mud siren, positive and/or negativepulse telemetry devices, an acoustic telemetry device, a tortional wavetelemetry device, or any other telemetry device(s) could be used insteadof or in addition to those depicted in FIGS. 2-4 to communicate with asurface unit or computer. Additionally, various combinations ofcommunication links (e.g., wireless, hardwired, etc.) may be employed toprovide selective communications between the surface unit and thetelemetry devices to suit the needs of particular applications.

Still further it should be understood that the telemetry devices, or anycombination thereof, used with the example systems described herein maybe positioned in various configurations about the downhole tool. Forexample, the devices may be positioned adjacent to each other or,alternatively, at some desired distance or spacing apart, with orwithout components disposed therebetween. The telemetry devices may beoriented vertically as shown in the examples, or one or more of thedevices may be inverted.

FIG. 5 is a schematic view, partially in cross-section, of still anotherexample telemetry system 500 including a downhole tool 501 havingmultiple downhole components and multiple wellbore telemetry devices. Asdepicted in the example system 500 of FIG. 5, the downhole tool 501includes two MWD tools 534 a and 534 b, two mud pulse telemetry devices538 a and 538 b, two pressure transducers 540 a and 540 b, and twosensors 542 a and 542 b.

A surface unit or computer 502, which may be similar or identical to oneor more of the example surface units 202, 302, and 402 of FIGS. 2, 3,and 4, respectively, may be communicatively and/or operationally coupledto the telemetry devices 538 a and 538 b and/or downhole components 548a and 548 b. As with the other example surface units 202, 302, and 404,the example surface unit 502 may be proximate (e.g., onsite) or remotelysituated (e.g., offsite) relative to the rig 10 and operationally and/orotherwise coupled to the telemetry systems, MWD tools 534 a and 534 b,and/or mud pulse telemetry devices 538 a and 538 b via any desiredcommunication links (not shown). The MWD tools 534 a and 534 b may beimplemented using devices similar or identical to those used toimplement the MWD tools 34, 234 a, 234 b, 334, and/or 434. Similarly,the mud pulse telemetry devices 538 a and 538 b may be implemented usingdevices similar or identical to those used to implement the mud pulsetelemetry devices 38, 238 a, 238 b, 338, and/or 438.

As depicted in FIG. 5, the downhole tool 501 houses the MWD tools 534 aand 534 b, the mud pulse telemetry devices 538 a and 538 b, and thedownhole components 548 a and 548 b. In the example of FIG. 5, thedownhole components 548 a and 548 b are depicted as formation evaluationtools, which may be used to test and/or sample fluid from a surroundingformation. Examples of such formation evaluation tools that may be usedto implement the tools 548 a and 548 b are described in published U.S.Patent Application No. 2005/01109538, which is incorporated by referenceherein in its entirety. As shown, the downhole components 548 a and 548b include stabilizer blades 552 a and 552 b with probes 554 a and 554 bfor drawing fluid into the downhole tool 501, and backup pistons 550 aand 550 b to assist in driving the probes 554 a and 554 b into positionagainst the wall of the wellbore 30. The formation evaluation components548 a and 548 b may enable various pressure testing and/or samplingprocedures to be performed. Although the example of FIG. 5 depicts twoformation evaluation components in the downhole tool 501, one or morethan two formation evaluation components may be used instead.

In the example of FIG. 5, the wellbore telemetry devices 538 a and 538 bare operationally coupled to the respective downhole components 548 aand 548 b. However, one or more wellbore telemetry devices may becoupled to one or more formation evaluation components. For example, twowellbore telemetry devices may be coupled to the same downhole componentor, alternatively, each wellbore telemetry device may be coupled to asingle, respective downhole component. Additionally, a variety offormation evaluation components may be coupled to one or both of thewellbore telemetry devices 538 a and 538 b. As used herein, “formationevaluation component” refers to a device for performing formationevaluation such as, for example, sampling, detecting formation pressurewhile drilling, measuring resistivity, nuclear magnetic measurements, orany other downhole tool used to evaluate a subterranean formation.

Multiple wellbore telemetry devices and/or systems such as thosedescribed in connection with the example systems herein may be used toprovide downhole tools with the ability to perform independent orintegrated downhole operations. For example, one wellbore telemetrysystem and/or telemetry device may be used in conjunction with adownhole formation evaluation component to perform various testingoperations, while a second telemetry device may be used to performresistivity operations. Additional wellbore telemetry systems and/ordevices may be provided as desired. In some cases it may be desirable touse certain wellbore telemetry systems or devices in conjunction withcertain downhole components to perform certain downhole operations.

Measurements taken using the wellbore telemetry devices may be comparedand analyzed. In this manner, duplicate or redundant measurements may betaken for calibration and/or verification purposes. Additionally,duplicate or redundant measurements may be taken at different positions(at the same or different times) to determine differences in theformation at various downhole locations. Measurements taken by differentcomponents may also be analyzed to determine, for example, performancecapabilities and/or formation properties.

The separate or individual functionality of the wellbore telemetrydevices may also be used to enhance power capabilities needed to performcontinuous or additional operations. Multiple wellbore telemetry devicesmay also be used to increase data transmission rates to the surfaceand/or to eliminate the need for batteries in the downhole tool. The useof multiple wellbore telemetry devices may also provide a backup systemin a case where one of the wellbore telemetry systems fails or isotherwise unable to function properly. Further, in cases where twodifferent wellbore telemetry systems and/or devices are used,alternative types of communications may be employed as desired or neededto provide more effective communications between a downhole tool and asurface unit. Still further, any desired communication medium orcombination of media may be used to implement the telemetry systemsdescribed herein. For example, any combination of wireless and/orhardwired media may be used to suit the needs of particularapplications. More specifically, wireless media may include drillingmud, electromagnetic signals, acoustic signals, etc., and hardwiredmedia may include wired drill pipe and/or any other media usingelectrical conductors.

As noted above in connection with the examples of FIGS. 2, 3, 4, and 5,the surface units 202, 302, 402, and/or 502 may be located onsite oroffsite (e.g., relative to the rig) and may be communicatively and/oroperationally coupled to one or more respective downhole tools viacommunication links (not shown). The communication links may beimplemented using any desired wireless and/or hardwired link capable oftransmitting data between wellbore telemetry devices and surface unitsor computers. In some examples, the communication link may be coupled toa wellbore telemetry device via an intermediary device such as, forexample, a pressure transducer. The communication link provides meansfor passing signals such as command, data, power or other signalsbetween the wellbore telemetry devices and the surface computer. Thesesignals may be used to control the downhole tool and/or to retrieve datacollected by the downhole tool. Preferably, but not necessarily, signalsare passed in real time to provide fast and efficient data collection,tool operation and/or response to wellbore conditions.

One or more communication links may be provided to operatively couplethe wellbore telemetry system(s) and/or device(s) to one or more surfaceunit(s). In this manner, each wellbore telemetry device and/or systemcan selectively communicate with one or more surface unit(s).Alternatively, such links may couple the wellbore telemetry system(s)and/or device(s). The telemetry device(s) may communicate with thesurface via a wellbore telemetry system. Various communication links maybe provided so that the wellbore telemetry devices and/or systems maycommunicate with each other and/or the surface unit(s) independently,simultaneously or substantially simultaneously, alternately (e.g., whileone telemetry device is actively communicating, other telemetry devicesare not actively communicating), and/or during selected (e.g.,predetermined) time frames or intervals.

The signals and/or other communications conveyed via the examplewellbore telemetry systems described herein may be used or manipulatedto enable the efficient flow of data or information. For example, theexample telemetry devices and/or systems may be selectively operated topass data from the downhole tool to the surface unit or computer. Suchdata may be passed from the telemetry devices and/or systems at similaror different frequencies, simultaneously or substantiallysimultaneously, and/or independently. The data and/or signals may beselectively manipulated, analyzed, or otherwise processed to generate anoptimum and/or desired data output. The data (e.g., the output data) maybe compared (e.g., to reference values, threshold values, etc.) and/oranalyzed to determine wellsite conditions, which may be used to adjustoperating conditions, locate valuable hydrocarbons, and/or perform anyother desired wellsite operations or functions.

The wired drill pipe drill string telemetry system described above(e.g., the example system of FIG. 3) may be used to provide relativelyhigh bandwidth transmission of MWD signals. However, the noisecancellation or suppression systems and methods described below inconnection with FIGS. 6-14 can be used with wired drill pipe to improvethe signal-to-noise ratio and increase the bandwidth of mud pulsetelemetry signals. More specifically, one or more pressure transducerscan be distributed or spaced along a section of wired drill pipe in anupper portion of a drill string. The pressure transducers may form alinear array that provides pressure signals that can be processed usingvertical seismic profiling techniques such as velocity filtering andstacking as described below to cancel, suppress, or reduce the effectsof downwardly propagating noise (e.g., mud pump noise and/or other rignoise) while enhancing upwardly propagating MWD signals (e.g., mud pulsetelemetry signals). In addition, the downwardly propagating noise may bereflected from obstacles in the drill string, resulting in upwardlypropagating noise. This upwardly propagating noise may also be removedfrom the MWD signals.

As used herein, the term “MWD signals” is used to refer to data that isgathered or collected downhole and sent to the surface via telemetry. Itis understood that a telemetry tool may be used to convey LWD signals orother types of data, but the term “MWD signals” is used for convenience.

In many MWD operations, especially offshore, the MWD mud pulse telemetryis limited to a very low data rate (<<10 bits/sec). The low data rateresults from a low signal-to-noise ratio, which can be caused by highnoise levels generated by mud pumps and other rig-based equipment, bymud pump noise in the frequency band of the MWD mud pulse telemetry, andby the exponential attenuation of the MWD signal with depth. Thepressure P(Z) measured a distance Z (m) from the mud pulser isattenuated according to P(Z)=P₀e^(−Z/L) where P₀ is the pressure at themud pulser, and where

$L = {a\sqrt{\frac{2\; B}{\eta\omega}}}$

is an effective length. The inner radius of the drill pipe is a (m); theangular frequency is ω (radians/S); the bulk modulus of the mud is B(Pa); and the viscosity is η (centipose). The attenuation increases withfrequency and with the viscosity of the drilling mud. (Reference: NewMud Pulse Telemetry Techniques for Deepwater Applications and ImprovedReal-Time Data Capabilities, SPE/ADC 67762, R. Hutin et al, 2001).Standard practice is to lower the mud pulse frequency to reduce theattenuation, and/or to shift the mud pulse frequency to avoidfrequencies where there is high mud pump noise. In deepwater operations,there may be up to 10,000 feet (3048 m) of cold water between the rigand the seabed. The cold water increases the drilling mud viscosity,which increases the attenuation, and thus further reducing the mud pulsefrequency and MWD telemetry data rate.

The systems and methods described below enable a relatively small amountof wired drill pipe (i.e., the entire drill string need not be composedof wired drill pipe) to enable relatively high bandwidth communicationsusing a mud pulse telemetry system. In particular, the noisecancellation, suppression, or reduction systems and methods describedherein utilize a relatively small amount of wired drill pipe andpressure transducers to enable a mud pulse telemetry system tocommunicate effectively at a higher data rate and/or at greater depths,thereby eliminating the need to use wired drill pipe along the entiredrill string to achieve a high data rate and/or to communicate atgreater depths. This eliminates the need to wire downhole drill stringcomponents such as positive displacement motors, jars, and heavy weightdrill pipe. Furthermore, by deploying the pressure transducers near theseabed, one avoids the increased attenuation due to the effect of coldseawater on the viscosity of the drilling mud.

FIG. 6 is a schematic view of an example drill string telemetry system600 including an array of pressure transducers 602, 604, and 606 tocancel, reduce, suppress, or separate downwardly propagating rig noise608 from an upwardly propagating MWD signal 610. While three pressuretransducers 602, 604, and 606 are depicted in the example of FIG. 6,fewer pressure transducers (e.g., one transducer in the wellbore area ofthe drill string) or more than three pressure transducers may be usedinstead. However, as described in greater detail below, the use ofmultiple pressure transducers may result in a greater signal-to-noiseratio for MWD signals generated by a mud pulse telemetry system thanpossible with, for example, a system employing only one pressuretransducer. The example drill string telemetry system 600 includes adrill string 612 that is composed of a wired drill pipe portion 614 anda normal drill pipe portion 616 that is not wired. In the example ofFIG. 6, the wired drill pipe portion 614 is located in the upper portionof the drill string 612 and the normal drill pipe portion 616 is locatedin the lower portion of the drill string 612. The example drill string612 also includes an MWD telemetry device 618 (e.g., an MWD pulser formud pulse telemetry) that is adjacent to a bit 620, which is disposed atthe bottom end of the example drill string 612.

The pressure transducers 602, 604, and 606, an example implementation ofwhich is depicted and described in connection with FIG. 7, may be spacedapart or separated along the wired drill string portion 614 of the drillstring 612 at, for example, intervals preferably about a quarterwavelength of the telemetry signals. For telemetry performed at lowerfrequencies (e.g., frequencies of a few Hertz), it may be desirable tospace the pressure transducers 602, 604, and 606 a hundred or moremeters apart, thereby requiring one or more of the pressure transducers602, 604, and 606 to be located in the borehole. Locating one or more ofthe pressure transducers 602, 604, and 606 in the borehole increases thedistance between the transducers and mud pumps and/or other sources ofrig noise, thereby further improving the signal-to-noise ratio of theMWD signal 610.

In general, the use of pressure transducers in connection with MWD mudpulse telemetry systems is known. One such use is described in U.S. Pat.No. 6,741,185, entitled “Digital Signal Receiver for Measurement WhileDrilling System Having Noise Cancellation,” the entire disclosure ofwhich is incorporated by reference herein. Typically, in contrast to theexample system of FIG. 6, these known systems locate one pressuretransducer near the mud pump(s), which are primary source of acousticnoise, and another pressure transducer in the standpipe. Thus, bothpressure transducers are located relatively close to the source of therig noise. Signals received from the sensors or transducers are thentypically processed or combined to cancel or reduce the effects of thenoise signals generated by the mud pump(s). The separation between thetransducer located near the mud pump(s) and the transducer in thestandpipe affects the degree to which mud pump noise can be canceled orsuppressed. A separation of about an eighth of a wavelength (i.e., thewavelength of the mud pulse telemetry signals) or about a quarter of awavelength is typically used to provide the greatest signal-to-noiseratio for the mud pulse telemetry signals. However, in practice, suchseparations on the surface near the rig are usually not possible due tothe low frequency and long wavelength of the mud pulse telemetry signalsand the limited path length associated with the pressure equipment onthe rig. Furthermore, pressure transducers 40 are normally located abovethe rig floor in the mud line 26. Mud pump noise is reflected by thetransition from the mud line to drill pipe, which results in complexstanding waves that make it difficult to filter the mud pump noise.

In contrast to the known use of pressure transducers noted above, in theexample of FIG. 6, the pressure transducers 602, 604, and 606 arelocated on the drill string 612 in relatively downhole locations,thereby reducing the surface noise to which the sensors 602, 604, and606 are subjected. The downhole locations of the transducers 602, 604,and 606 and the spacing between the transducers 602, 604, and 606 may beselected based on the acoustic velocity in drilling mud and thefrequency at which mud pulse telemetry signals are transmitted by theMWD telemetry device 618. More specifically, the acoustic velocity indrilling mud ranges between about 1 km/sec to 1.5 km/sec, and mud pulsetelemetry signals are typically transmitted at a frequency of betweenabout 1 Hz and 24 Hz. The table below provides quarter wavelength sensorspacing in meters for different acoustic velocities and mud pulsetelemetry transmission frequencies.

Quarter-Wavelength Spacing Mud Pulse Freq. 1 km/sec. 1.5 km/sec. 1 Hz250 m 375 m 12 Hz 21 m 31 m 24 Hz 10 m 16 m

In view of the foregoing quarter wavelength information, a particularexample in connection with the example configuration of FIG. 6 is nowprovided. For example, assume a final bit run begins at a measured depthof 7 kilometers and that the total depth to which the well is to bedrilled is 10 kilometers. At the beginning of the final bit run, the MWDtelemetry device or pulser 618 may be run into the borehole such thatthe normal drill pipe 616 is about 6.5 km in length and the wired drillpipe 614 is about 0.5 km in length. Special subs (e.g., the example sub700 depicted in FIG. 7) containing the pressure transducers 602, 604,and 606, batteries, electronics, processors, communications circuitry,etc. may be uniformly spaced between selected wired drill pipe segmentsin the wired drill pipe 614 portion of the drill string 612. Forexample, three such subs could be spaced apart by 250 meters to providequarter wavelength spacing for 1 Hz MWD signals. The subs (e.g., locatedat the pressure sensors 602, 604, and 606) can communicate with asurface computer or unit via the communication channel provided by thewired drill pipe 614. In one example, the signals from the pressuretransducers 602, 604, and 606 may be sampled and digitized atapproximately 200 Hz. The digitized information associated with thetransducers 602, 604, and 606 may then be transmitted to a surfacecomputer for further processing via the wired drill pipe 614 or otherdrill string telemetry (e.g., as described below in connection with FIG.13). In the example where the drill string telemetry is the wired drillpipe 614, data rates of between about 10 to 50 kbits/sec. are possible,thereby easily accommodating the bandwidth needed to transmit thedigitized information.

As drilling continues, an additional 3 km of wired drill pipe 614 isadded to reach the total depth of 10 km. In this manner, the distancesbetween the MWD pulser 618 and the pressure transducers 602, 604, and606 do not increase with drilling. As a result, the signal-to-noiseratio of the MWD signal 610 does not degrade with depth. On thecontrary, the signal-to-noise ratio may be increased by addingadditional pressure sensors (not shown) to the drill string 612.Additionally, the signal-to-noise ratio improves as the distance betweenthe pressure transducers and surface noise sources increases with depth.In deepwater offshore, the attenuation of the downwardly propagatingnoise due to the effect of cold water on the drilling mud viscosity isbeneficial when the pressure transducers are located near the seabed.

FIG. 7 is a cross-sectional view of an example sub 700 that may be usedto implement the pressure transducers 602, 604, and 606 in the exampledrill string telemetry system 600 of FIG. 6. The example sub 700includes a collar 702 having a passage 704 through, toroids 706 and 708,electronics 710, batteries 712, and a pressure transducer 714. The sub700 allows telemetry signals to pass through it, and can itself receiveand send telemetry signals. In one example, the toroids 706 and 708 areconnected by a wire or other electrical connection. In the example ofFIG. 7, the pressure transducer 714 is configured to measure pressure inthe interior of the sub 700 (e.g., in the passage 704). However, anannular or exterior pressure measurement could be used instead of or inaddition to the interior pressure measurement. The electronics 710,which are powered by the batteries 712, may include interface and signalconditioning circuitry or programming to condition signals received fromthe pressure transducer 714. The electronics 710 may also includecommunications circuitry to enable pressure information (e.g., measuredpressure values) to be conveyed via the wired drill pipe 614.Specifically, the communications circuitry may be configured to providevarying electrical currents to the toroids 706 and 708 to magneticallycouple the pressure signal information to a surface unit (e.g., similaror identical to the surface unit 302 of FIG. 3) via the wires in thewired drill pipe 614. Transformers other than toroids, and/or electricalcontacts may be used to connect the sub 700 to the wired drill pipe.

The pressure transducers 602, 604, and 606 of FIG. 6 form an array thatmay be used to provide a plurality of pressure signals that can beprocessed to improve the signal-to-noise ratio of the MWD signal 610.

As described in greater detail in conjunction with FIGS. 8-14 below, thesignals from the pressure sensors 602, 604, and 606 may be processed toenhance the upwardly propagating MWD signal 610 while decreasing theeffects of downwardly propagating surface noise (e.g., the mud pumpnoise 608 of FIG. 6) on the MWD signal 610. As a result, thesignal-to-noise ratio of the MWD signal 610 can be increased.

The method exploits the fact that the mud pump and other noise from therig initially propagates downwardly, while the MWD mud pulse signalpropagates upwardly. This is a velocity filtering technique. The signalsat the pressure transducers 602, 604, and 606 may be time-shiftedcorresponding to a downwardly propagating wave and averaged to estimatethe downwardly propagating noise signal (e.g., an enhanced form of themud pump noise signal 608). This estimated noise signal may thensubtracted from each of the signals provided by the pressure transducers602, 604, and 606 to provide corrected pressure signals. The correctedpressure signals are then time-shifted corresponding to an upwardlypropagating wave and averaged to enhance the upwardly propagating MWDsignal 610. As described further below, the time-shifting and stacking(i.e. averaging) are performed by determining the velocity of theacoustic waves or signals associated with the mud pump noise 608 and theMWD signal 610. The velocity of the acoustic waves, which may varyslowly over time, can be determined using, for example, across-correlation technique as described later.

FIG. 8 depicts an example manner in which the example drill stringtelemetry system 600 of FIG. 6 may be used to detect downwardlypropagating noise. The technique described in connection with FIG. 8uses signals associated with the pressure transducers 602, 604, and 606of FIG. 6, corresponding to respective drill string locations Z1, Z2,and Z3 in FIGS. 6 and 8. The three vertical axes correspond torespective times T1, T2, and T3 during which mud pump noise 608propagates downwardly past locations Z1, Z2 and Z3 along the drillstring 612. As indicated in FIG. 8, the waveform of the downwardlypropagating noise remains relatively unchanged over the array ofpressure transducers provided there are no major obstacles in the drillpipe within the array. The pressure transducers 602, 604, and 606generate respective pressure signals S1(t), S2(t) and S3(t) as functionsof time in response to the downwardly propagating noise waveform, shownat times T1 801, T2 802, and T3 803. More specifically, pressuremeasurements are obtained at discrete times {t1, t2, t3, . . . }, withconstant time increments of Δt. The time increment Δt should besufficiently short to obtain several measurements per cycle. It isunderstood that the notation S1(t) actually represents many discretemeasurements; that is, the pressure measurements are made and recordedat large number of discrete times. Noise from the rig mud pumps and/orother surface equipment propagates downwardly with velocity V,represented by the diagonal line 804 in FIG. 8. There are similarsignals at the pressure transducers 602, 604, and 606 whenZ1−(V·T1)=Z2−(V·T2)=Z3−(V·T3). The signals from the pressure transducers602, 604, and 606 may then be time-shifted and averaged to provide anestimate of the downwardly propagating noise (e.g., the mud pump noise608) as a function of time according to the equationN_(D)(t)={S1(t)+S2(t+(Z2−Z1)/V)+S3(t+(Z3−Z1)/V)}/3. In FIG. 8, this isequivalent to moving waveforms 802 and 803 in alignment with waveform801 and then averaging the waveforms. In determining the estimateddownwardly propagating noise N_(D)(t), it is assumed that the signalsS1(t), S2(t) and S3(t) have been properly normalized to account for anyattenuation between the pressure transducers and to account forvariations in the sensitivities of the pressure transducers. Theestimated noise function N_(D)(t) can then be used to correct thesignals received at each of the pressure transducers 602, 604, and 606to produce corrected pressure transducer signals R1(t), R2(t), and R3(t)as set forth below.

R1(t)=S1(t)−N _(D)(t)

R2(t)=S2(t)−N _(D)(t+(Z2−Z1)/V)

R3(t)=S3(t)−N _(D)(t+(Z3−Z1)/V)

As shown in FIG. 9, the corrected pressure transducer signals mayinclude some residual downwardly propagating noise 910, which may nothave a significant impact on an upwardly propagating signal, representedby 901, 902, and 903 at the times T1, T2 and T3. The corrected pressuretransducer signals R1(t), R2(t), and R3(t) can then be time-shifted andaveraged to enhance the upwardly propagating signal, which may be, forexample, the MWD signal 610 of FIG. 6. The velocity of the upwardlypropagating signal V is represented by the diagonal line 905 in FIG. 9.More specifically, the upwardly propagating signal is similar at each ofthe pressure transducer locations Z1, Z2, and Z3 whenZ1+(V·T3)=Z2+(V·T2)=Z3+(V·T1). The time-shifted, upwardly propagatingsignal can then be represented using the expressionF_(U)(t)={R1(t+(Z3−Z1)/V)+R2(t+(Z2−Z1)/V)+R3(t)}/3. The waveforms 901and 902 are essentially time-shifted to coincide with waveform 903 andthen averaged.

Initially, the velocity V can be estimated from the physical propertiesof the drilling mud. However, a more precise determination can be madeby cross-correlation of downwardly propagating noise or bycross-correlation of the upwardly propagating MWD signals. For example,consider the signals S1(t) and S2(t). A sliding window of m data pointsis used in the cross-correlation. The length of the time window, m Δt,should be sufficiently long to contain a few cycles. The mean value forthe signal measured at

${Z_{1}\mspace{14mu} {is}\mspace{14mu} \overset{\_}{S_{1}}} = {\frac{1}{m}{\sum\limits_{k = 0}^{m - 1}\; {S_{1}\left( t_{k + i} \right)}}}$

for {t_(i), t_(i+1), t_(i+2), t_(i+3), . . . t_(i+m−1)}, and the meanvalue for the signal measured at Z2 is

$\overset{\_}{S_{2}} = {\frac{1}{m}{\sum\limits_{k = 0}^{m - 1}\; {{S_{2}\left( t_{k + j} \right)}\mspace{14mu} {for}\mspace{14mu} {\left\{ {t_{j},t_{j + 1},t_{j + 2},t_{j + 3},\ldots \mspace{14mu},t_{j + m - 1}} \right\}.}}}}$

Note that the two time windows will be different, i.e. i≠j. Thecross-correlation function C12(d) between S1(t) and S2(t) is defined as

${C_{12}(d)} = {\sum\limits_{k = 0}^{m - 1}\; \left\{ {\left\lbrack {{S_{1}({tk})} - \overset{\_}{S_{1}}} \right\rbrack \cdot \left\lbrack {{S_{2}\left( t_{j} \right)} - \overset{\_}{S_{2}}} \right\rbrack} \right\}}$

where j=k+d. The cross-correlation function C12(d) achieves a maximumvalue when the time lag is given by

${{d \cdot \Delta}\; t} = {\frac{Z_{2} - Z_{1}}{V}.}$

Hence, the velocity is obtained by calculating the cross-correlationfunction C12(d), finding the value for d corresponding to the maximum ofC12(d), and then using

$V = {\frac{\left( {Z_{2} - Z_{1}} \right)}{{d \cdot \Delta}\; t}.}$

This velocity can then be used for shifting and stacking signals, and toobtain the estimate of downwardly propagating noise N_(D)(t). Velocitiescan be similarly calculated for all adjacent pairs of pressuretransducers, and the results averaged to increase accuracy. Analternative approach and/or complimentary approach is to compute thecross-correlation function for upwardly propagating waves to obtain thevelocity V.

FIG. 10 shows an example of a method that uses an algorithm to separatedownwardly propagating waves from upwardly propagating waves. In theparticular example shown in FIG. 10, a downwardly propagating noisesignal may be separated from an upwardly propagating MWD signal. Thosehaving skill in the art will realize that the principles of theinvention may be used on other types of signals as well. Further, inaddition to using the example methods described herein, f-k processing,as is known in the seismic interpretation art, may be used inconjunction with other principles of the present invention to separatedownwardly propagating waves from upwardly propagating waves.

The example method shown in FIG. 10 includes measuring pressure signalsat a plurality of locations at a plurality of times, at 1001. This maybe accomplished by positioning two or more pressure sensors within adrilling system. The pressure sensors may for part of a sub that ispositioned within the drill string, or they may form part of a wirelinetool that is positioned within the wellbore, for example in the drillstring. Other examples include positioning pressure sensors in casing,possible for casing drilling or in a coiled tube. The manner in whichthe pressure sensors are positioned within the drilling system is notintended to limit the invention. In one particular example, threepressure sensors may be used, although other numbers of pressure sensorsmay be used.

In one example, the method includes measuring the pressure at twolocations, represented by S1(t) and S2(t). The pressure measurements maybe made at two or more different times, such as t1 and t2. In anotherexample, the pressure measurements may be made at three or morelocations, S1(t), S2(t), and S3(t) at three or more different times, t1,t2, t3, etc. In one example, the times t1, t2, t3 are equally spaced.The method may next include transmitting the measured pressure signalsto the surface, at 1002. In one example, the pressure data may betransmitted through a wired drill pipe. In another example, the pressuredata may be transmitted using another telemetry device, such as anelectromagnetic telemetry tool. In still another example, the pressuredata may be transmitted through a wireline.

The method may next include determining the velocity of signals in thewellbore fluid. In one example, the signal velocity may be known ormeasured in any manner known in the art. In the example method shown inFIG. 10, determining the velocity may include computing one or morecross-correlation functions, at 1003. In one example, across-correlation function for the first two pressure measurementsS1(t), S2(t) is represented by C₁₂(d). In one particular example, thecross-correlation function is represented as

${C_{12}(d)} = {\sum\limits_{k = 0}^{m - 1}\; {\left\{ {\left\lbrack {{S_{1}({tk})} - \overset{\_}{S_{1}}} \right\rbrack \cdot \left\lbrack {{S_{2}\left( t_{j} \right)} - \overset{\_}{S_{2}}} \right\rbrack} \right\}.}}$

In this example, the cross-correlation function achieves a maximum valuewhen the time lag is given by

${{d \cdot \Delta}\; t} = {\frac{Z_{2} - Z_{1}}{V}.}$

Thus, by determining the maximum value for the cross-correlationfunction, the velocity V of the downwardly propagating noise signal maybe determined.

The method may next include time-shifting and stacking the pressuresignals to obtain the downwardly propagating noise signal, at 1004. Inone example, there are two pressure signals S1(t) and S2(t), and one ofthe pressure signals is time-shifted so that the pressure signals may bestacked to obtain the downwardly propagating noise signal. In anotherexample, three pressure signals, S1(t), S2(t), and S3(t) aretime-shifted and stacked, according to the following equation:N_(D)(t)={S1(t)+S2(t+(Z2−Z1)/V)+S3(t+(Z3−Z1)/V)}/3. Those having skillin the art will be able to devise other equations for time-shifting andstacking, as well as be able to devise equations for time-shifting andstacking a number of pressure signals other than 3. The above equationsare provided only as an example.

The method may next include correcting the pressure signals bysubtracting the downwardly propagating noise, at 1005. In the case wherethere are three pressure sensors, one example of correcting the pressuremeasurement includes using the equations R1(t)=S1(t)=N_(D)(t),R2(t)=S2(t)−N_(D)(t+(Z2−Z1)/V), and R3(t)=S3(t)−N_(D) (t+(Z3−Z1)/V).

The method may include stacking the corrected signals to obtain theupwardly propagating MWD signal, at 1006. This may be done for anynumber of pressure measurements. For example, in the case with twopressure measurements, one of the corrected signals may be time-shiftedand stacked with the other signal to provide the upwardly propagatingMWD signal. In another example, three corrected pressure signals aretime-shifted and stacked, in accordance with the following equation:F_(U)(t)={R1(t+(Z3−Z1)/V)+R2(t+(Z2−Z1)/V)+R3(t)}/3. Those havingordinary skill in the art will be able to devise methods fortime-shifting and stacking other numbers of corrected pressure signals.

Referring to FIG. 6, the downwardly propagating mud pump noise 608 maybe reflected from obstacles in the drill string 616 such as the mudpulser 618, the bit 620, or a change in the drill string's innerdiameter. FIG. 11 illustrates incident mud pump noise 1102 reflectingfrom a change in drill pipe inner diameter 1110 located at depth Zs. Forexample, pressure transducer 606 is located at Z3 and it measures adownwardly propagating noise pulse at time Ta. At time Tb, thedownwardly propagating noise pulse reaches the change in diameter 1110.Part of the noise pulse is transmitted 1106, and part is reflected 1105.The reflected, upwardly propagating noise waveform will be similar tothe incident noise waveform, except that it may acquire a phase shift φand will be reduced in amplitude by the factor A. At time Tc, thereflected noise pulse 1105 propagates upwardly past the pressuretransducer 606, having acquired the time lag Tc−Ta. The reflected noiseN_(U)(t) is thus related to the downwardly propagating noise pulse atlocation 606 by N_(U)(t)=Ae^(iφ)·N_(D)(t+Tc−Ta), where N_(D)(t) has beendetermined as previously explained. The cross-correlation of R3(t) andN_(D)(t) can then be used to determine Tc−Ta, φ, and A as explainedbelow. Since permanent obstacles in the drill string cause thereflection, these three quantities will remain constant with time andmany measurements can be averaged for increased accuracy. Once thesethree quantities have been determined, an estimate of the upwardlypropagating noise N_(U)(t) may be obtained. Then N_(U)(t) may besubtracted from R3(t) to further improve the signal-to-noise ratio via−{tilde over (R)}3(t)=R3(t)−N_(U)(t). The same process can be applied tothe other pressure transducers' signals to remove the reflected mud pumpnoise. The three signals now having been corrected for downwardlypropagating and upwardly propagating mud pump noise can be time shiftedand stacked for improved signal-to-noise,

{tilde over (F)}{tilde over (F_(U))} (t)={{tilde over(R)}1(t+(Z3−Z1)/V)+{tilde over (R)}2(t+(z2−z1)/V)+{tilde over(R)}3(t)}/3.

One example of the details of obtaining the three quantities, Tc−Ta, φ,and A is now described. Suppose that the true MWD mud pulse signal atpressure transducer 606 is M3(t). After the downwardly propagating mudpump noise has been removed, the corrected signal at 606 can be writtenas R3(t)=M3(t)+N_(U) (t), i.e. it is composed of the MWD mud pulsesignal and the reflected mud pump noise. The downwardly propagating mudpump noise has been obtained. The cross-correlation function C3D(d)between the corrected R3(t) and the estimated N_(D)(t) is

${C_{3\; D}(d)} = {\sum\limits_{k = 0}^{m - 1}\; \left\{ {\left\lbrack {{S_{1}({tk})} - \overset{\_}{S_{1}}} \right\rbrack \cdot \left\lbrack {{S_{2}\left( t_{j} \right)} - \overset{\_}{S_{2}}} \right\rbrack} \right\}}$

where j=k+d and where R3 and N_(D) are the mean values of R3(t) andN_(D)(t) calculated over the appropriate time windows. Thecross-correlation function C3D(d) is maximum when d=(Tc−Ta)/Δt. If thecross-correlation is calculated many times and the results averaged,then there should be no net correlation between the upwardly propagatingnoise, N_(U) (t), and the MWD mud pulse signal, M3(t). However, thedownwardly propagating mud pump noise, N_(D)(t), and the upwardlypropagating mud pump noise, N_(U) (t), will be correlated. Thereflection parameters are given by

${{A \cdot ^{\varphi}} = \frac{\langle{C_{3\; D}(d)}\rangle}{\left( {m - 1} \right){\langle\sigma_{N}^{2}\rangle}}},$

where < > denotes an average over many measurements. The standarddeviation of the downwardly propagating mud pump noise, σ_(N), iscalculated using

$\sigma_{N} = {\frac{1}{m - 1}\sqrt{\sum\limits_{k = 0}^{m - 1}\; \left( {{N_{D}\left( t_{i + k} \right)} - \overset{\_}{N_{D}}} \right)^{2}}}$

where the time window corresponds to that which gives the maximum valuefor C3D(d).

FIG. 12 shows a method for removing reflected, upwardly propagating mudpump noise. The method may first include obtaining pressure signals froma plurality of locations, at 1201. In one example, the pressure signalsmay comprise raw pressure measurements from pressure sensors, such aspressure transducers. In another example, the pressure signals maycomprise corrected pressure signals that have been corrected using oneor more of the above described correction techniques. The source of thepressure signals is not intended to limit the invention.

The method may next include computing the cross-correlation function, at1202. In one example, the cross-correlation function between thepressure signal and the previously computed downwardly propagating pumpnoise. Such a cross-correlation function may have the form

${C_{3\; D}(d)} = {\sum\limits_{k = 0}^{m - 1}\; {\left\{ {\left\lbrack {{R_{3}({tk})} - \overset{\_}{R_{3}}} \right\rbrack \cdot \left\lbrack {{N_{D}\left( t_{j} \right)} - \overset{\_}{N_{D}}} \right\rbrack} \right\}.}}$

The maximum value for the cross-correlation function may enable thedetermination of the time between when the downwardly propagating noisesignal passes the pressure sensor and when the reflected, upwardlypropagating noise signal passes the pressure sensor (e.g., Tc−Ta). Thecomputation of the cross-correlation function and its maximum may beperformed many times and the results averaged.

Next, the method may include calculating the standard deviation of thedownwardly propagating noise for the time window that corresponds to themaximum value for the cross-correlation function, at 1203. Next themethod may include computing a reflection coefficient for the mud pumpnoise, at 1204). In one example, this is performed by averaging theequation

${{A \cdot ^{\varphi}} = \frac{\langle{C_{3\; D}(d)}\rangle}{\left( {m - 1} \right){\langle\sigma_{N}^{2}\rangle}}},$

over many measurements.

Next, the method may include repeating the above process for theplurality of pressure transducers, at 1205. This step may be applied toa plurality of pressure measurements, when more than one pressure signalis obtained. In other examples, this step may be omitted.

The method may next include subtracting the upwardly propagating mudpump noise from the pressure signal, at (1206). In one example, theupwardly propagating mud pump noise may be subtracted from the pressuresignal using the equation −{tilde over(R)}3(t)=R3(t)−Ae^(iφ)N_(D)(t+Tc−Ta). In one example, the pressuresignal is a corrected pressure signal that has been corrected using oneor more of the techniques described herein.

Next, the method may include time-shifting and stacking the plurality ofpressure signals to obtain the upwardly propagating MWD signal, at 1207.In one example, three corrected pressure signals may be used to timeshift and stack the signals. In particular, the three signals may betime shifted and stacked using the equation {tilde over (F)}{tilde over(F_(U))} (t)={{tilde over (R)}1(t+(Z3−Z1)/V)+{tilde over(R)}2(t+(z2−z1)/V)+{tilde over (R)}3(t)}/3. Those having ordinary skillin the art will be able to devise equations for time-shifting andstacking more or less than three pressure signals.

There are other algorithms for separating and removing downwardlypropagating signals from upwardly propagating signals which can beapplied to improve the MWD signal-to-noise ratio. For example, variousmathematical techniques have been developed for Vertical SeismicProfiling (VSP) to separate and remove downwardly propagating seismicwaves from reflected, upwardly propagating seismic waves. See forexample, Chapter 5 in “Vertical Seismic Profiling, Volume 14A”, by BobHardage, Geophysical Press, London 1985, and “Vertical SeismicProfiling, Volume 14B”, by N. Toksov and R. Stewart, Geophysical Press,London 1984. One example is f-k velocity filtering, where seismicmeasurements are obtained at a number of specific depths versus time toprovide a two-dimensional data set in depth and time, F(Z,t). FIGS. 8and 9 illustrate a similar two-dimensional data set with coordinates inspace and time for pressure transducers 602, 604 and 606. In f-kfiltering, a two-dimensional Fourier transform is then applied to F(Z,t)to obtain a corresponding data set in frequency and wavenumber space orG(f,k). FIG. 13 illustrates the transformed data set in (f,k) space.Positive values of the wavenumber k correspond to downwardly propagatingwaves and are located in quadrant 1302. Negative values of thewavenumber k correspond to upwardly propagating waves and are located inquadrant 1301. In f-k filtering, data in quadrant 1302 are multiplied bya very small number (e.g. 0.001) to reduce the effects of downwardlypropagating waves. The inverse Fourier transform is then applied to themodified G(f,k) data. Most of the downwardly propagating waves are thusremoved from the final data set in (Z,t) space. If some frequencies fare associated with noise (e.g. mud pump noise), then G(f,k) pointsassociated with these frequencies may also be multiplied by a smallnumber before the inverse Fourier transform is applied. The correcteddata in (Z,t) space can be time-shifted (for upwardly propagatingsignals) and averaged to enhance the MWD mud pulse signal.

Further vertical seismic profiling techniques such as, for example,removing multiples may be used to enhance the upwardly propagatingsignal 904. Multiples refer to multiple reflections between two or moreobstacles. For example, an upwardly propagating MWD pulse signal mayreflect from a change in drill string's inner diameter and result in adownwardly propagating signal. This in turn may reflect from the MWDpulser and produce a second, time-delayed upwardly propagating signal orghost. Similarly, multiple reflections of the noise can result in noisemultiples. To eliminate or reduce such multiples, a relatively orsubstantially constant diameter within the drill string may be used. Inother words, the various drill pipe sections and subs may be configuredto provide such a substantially constant inner diameter.

FIG. 14 is a cross-sectional view of another example manner in which oneor more pressure transducers may be disposed within a drill string. Theexample of FIG. 14 is implemented using a top drive system 1400 inconjunction with a wireline cable 1402 instead of wired drill pipe todeploy a pressure transducer 1404 inside the drill pipe. The pressuretransducer 1404 may be lowered via the wireline cable 1402 into thedrill pipe a distance that locates the pressure transducer 1404 aquarter wavelength from the transducer in the standpipe (not shown). Inoperation, the wireline cable 1402 passes through a packer 1406 locatedabove a top drive unit 1408. When adding a new stand of drill pipe, thecable 1402 and pressure transducer 1404 are retracted above the topdrive system 1400. Then, when the new stand of drill pipe is in place,the pressure transducer 1404 is lowered into the drill pipe.

The wireline cable 1402 and the pressure transducer 1404 may be lowereda couple or few hundred meters into the drill pipe, thereby enabling arelatively small winch to be used and enabling the cable 1402 and thepressure transducer 1404 to be lowered or retracted relatively quickly.

While the example of FIG. 14 depicts the use of a single pressuretransducer, multiple pressure transducers or sensors may also bedeployed into a drill pipe using a wireline packer configuration similarto that shown in FIG. 14. In particular, an array of miniature pressuretransducers such as, for example, fiber optic pressure transducersmounted in a fiber optic cable may be sized to pass through a wirelinepacker and into a drill string.

The invention can be applied to other methods of drilling where mudpulse telemetry is employed. In casing drilling, casing is used insteadof drill pipe to transmit fluids and mechanical forces between the rigand the drill bit. The MWD system can be removed afterwards while thecasing remains and is cemented in the borehole. Pressure transducersdeployed inside casing using wireline cable or fiber-optic cable can beused to increase the signal to noise ratio of the mud pulse telemetrysystem. In coiled tubing drilling (CTD), a continuous metal tubular isinitially coiled on a drum and spooled out as the well is drilled. Theinvention can be applied to CTD by deploying wireline or fiber-opticpressure transducers in the upper portion of the tubing.

In offshore drilling, risers are often used to return the drilling mudand cuttings to the rig. Risers consist of tubular components thatsurround the drill pipe and are attached to the blow-out preventor (BOP)on the seabed and connect to the rig. An array of pressure transducersmay be mounted on the riser, rather than being located inside the drillpipe or attached to the drill pipe. These pressure transducers transmitdata to the rig via hardwired connections, or by wireless means such aselectromagnetic or acoustic waves. They may be powered by batteries orfrom the surface. These pressure transducers measure the pressure in theannulus between the drill pipe and the riser. The downwardly propagatingnoise and the upwardly propagating MWD mud pulse signals may also bepresent in this annular gap between the drill pipe and the riser.

Thus, as set forth above in connection with the description of theexamples in FIGS. 6-14, the deployment of one or more pressuretransducers within a drill string may be used to enhance drill stringtelemetry signals. In particular, the one or more pressure transducersmay be used to substantially reduce the effects of downwardlypropagating noise signals (e.g., mud pump noise and/or other rig noise)on upwardly propagating telemetry signals (e.g., MWD signals). In oneimplementation, one or more pressure transducers disposed along a wireddrill pipe portion of a drill string form a pressure sensor array. Thepressure transducers may be spaced apart a distance that facilitates theuse of an adaptive filtering technique. For example, the pressuretransducers may be spaced about a quarter wavelength (i.e., a quarterwavelength of upwardly propagating MWD signals) apart to enable orfacilitate the use of a velocity filtering or vertical seismic profilingtechnique. In addition, the pressure transducers may be spaced at otherdistances, such as half of a wavelength, three-quarters of a wavelength,and multiples thereof, or another distance that is selected based on twoor more telemetry frequencies that are planned to be used. As describedabove, such a velocity-based profiling technique can be used to estimatedownwardly propagating noise (e.g., from a mud pump), which can then beused to correct (e.g., via subtraction) the pressure signals receivedfrom the pressure sensors. The corrected pressure sensor signals canthen be time-shifted and stacked (e.g., averaged) to provide, forexample, an enhanced (e.g., increased signal-to-noise ratio) upwardlypropagating MWD signal. In addition, mud pump noise and other rig noisethat are reflected from obstacles and propagate upward can also bedetected and substantially removed.

Thus, in the example drill string telemetry systems described hereinthat use, for example, both mud pulse telemetry and wired drill pipe toenable communications between the MWD tools and surface equipment, thenoise cancellation systems and techniques described herein in connectionwith FIGS. 6-14 may be used to improve (i.e., increase) thesignal-to-noise ratio of the upwardly propagating telemetry signals. Animproved or increased signal-to-noise ratio for the upwardly propagatingtelemetry signals enables an increased data rate for mud-based drillstring telemetry systems and/or may enable the useful depth of amud-based drill string telemetry system to be increased.

Further, in systems employing wired drill pipe and mud pulse telemetry,failure of the wired drill pipe below the pressure transducersnevertheless enables the wired drill pipe to be used as a communicationmedium for the pressure transducers which, in turn, can be used in theforegoing manners to improve communications via the mud pulse telemetrysystem. Still further, the noise reduction, suppression, or cancellationsystems and techniques described in connection with FIGS. 6-14 may beparticularly useful to achieve high drill string telemetry communicationrates without having to use wired drill pipe along the entire length ofthe drill string. In other words, a mud pulse telemetry system can beused and its data rate can be increased when used in conjunction withthe noise cancellation techniques and systems described herein inconnection with FIGS. 6-14. Specifically, only an upper portion of thedrill string including one or more pressure transducers needs to becomposed of wired drill pipe to enable the pressure transducers tocommunicate with surface equipment. Such a configuration may beparticularly advantageous when used in, for example, deepwater wells.

While the invention has been described as detecting and substantiallyremoving downwardly propagating noise to improve the signal to noiseratio of upwardly propagating signal, the same approach can be appliedto improve the signal to noise ratio of a downwardly propagating signal.For example, it is sometimes necessary to transmit a signal from thesurface to the MWD system. Such downlink transmissions are used tochange the data acquisition mode of the MWD system, or to change thedirection of a steerable drilling system. The downlink can be performedby generating pressure pulses at the surface that are detected by theMWD system. An array of pressure transducers can be distributed amongvarious MWD tools, and the signals processed in a similar manner asdescribed for the uplink transmissions. In the case of a downlink, thedownhole noise source may be the MWD mud pulse telemetry. Velocityfiltering can be applied to estimate and remove the mud pulse signal andto enhance the signal sent from the surface. The processing could bedone in the MWD system.

It will be understood from the foregoing description that the examplesystems and methods described herein may be modified from the specificembodiments provided. For example, the communication links describedherein may be wired or wireless. The pressure measured at the sub 700may be transmitted to the surface as digital or analog information. Theexample devices described herein may be manually and/or automaticallyactivated or operated to perform the desired operations. Such activationmay be performed as desired and/or based on data generated, conditionsdetected, and/or results from downhole operations. Other algorithmswhich separate upwardly propagating and downwardly propagating waves arealso envisioned in the invention. For example, the velocity has beentreated as a constant, independent of frequency. However, it is possibleto modify the algorithm to include situations where the velocity is afunction of frequency. The final processing has been described as beingperformed in a surface computer; however, it may be implemented indownhole sub 700 and the processed results sent to the surface.

The foregoing description and example systems and methods providedthereby are for purposes of illustration only and are not to beconstrued as limiting. Thus, although certain apparatus and methods havebeen described herein, the scope of coverage of this patent is notlimited thereto. To the contrary, this patent covers all embodimentsfairly falling within the scope of the appended claims either literallyor under the doctrine of equivalents.

What is claimed is:
 1. A method of signal processing, comprising:providing at least a first pressure sensor and a second pressure sensorspaced in a drilling system; and using an algorithm to separate thedownwardly propagating waves from the upwardly propagating waves.
 2. Themethod of claim 1, wherein using an algorithm to separate the downwardlypropagating waves from the upwardly propagating waves comprises:determining a velocity of pressure signals in a wellbore; time-shiftingand stacking pressure signals from at least the first pressure sensorand the second pressure sensor to determine a downwardly propagatingnoise signal; and subtracting the downwardly propagating noise signalfrom at least the signal from the first pressure sensor.
 3. The methodof claim 2, further comprising: subtracting the downwardly propagatingnoise signal from the signal from at least the second pressure sensor;and time-shifting and stacking at least the signal from the firstpressure sensor and the signal from the second pressure sensor to obtainthe upwardly propagating data signal.
 4. The method of claim 3, whereinproviding at least a first pressure sensor and a second pressure sensorcomprises providing the first pressure sensor, the second pressuresensor, and a third pressure sensor, and wherein: time-shifting andstacking at least the signal from the first pressure sensor and thesignal from the second pressure sensor to determine a downwardlypropagating noise signal comprises time-shifting and stacking the signalfrom the first, second, and third pressure sensors; and whereinsubtracting the downwardly propagating noise signal from at least thesignal from the first pressure sensor comprises subtracting thedownwardly propagating noise signal from the signals from the first,second, and third pressure sensors.
 5. The method of claim 4, wherein:time-shifting and stacking the signals from the first, second, and thirdpressure sensors to determine the downwardly propagating noise signal isperformed using the following equation:N _(D)(t)={S1(t)+S2(t+(Z2−Z1)/V)+S3(t+(Z3−Z1)/V)}/3; and whereinsubtracting the downwardly propagating noise signal from the signalsfrom the first, second, and third pressure sensors is performed usingthe following equations:R1(t)=S1(t)−N _(D)(t),R2(t)=S2(t)−N _(D)(t+(Z2−Z1)/V),R3(t)=S3(t)−N _(D)(t+(Z3−Z1)/V).
 6. The method of claim 2, furthercomprising transmitting pressure signals from at least the first andsecond pressure sensor to a surface location.
 7. The method of claim 6,wherein the pressure signals are transmitted through one of a wireddrill pipe, an electromagnetic telemetry tool, a wireline cable, afiber-optic cable, and a wireless communication device.
 8. The method ofclaim 3, wherein the upwardly propagating data signal comprises an MWDsignal.
 9. The method of claim 2, wherein determining the velocity ofsignals in the wellbore fluid comprises: determining at least onecross-correlation function between the signals from at least the firstpressure sensor and the second pressure sensor for downwardlypropagating waves; determining a maximum value for the at least onecross-correlation function; and determining the velocity of the signalsin the wellbore fluid based on a maximum value of the at least onecross-correlation function.
 10. The method of claim 9, wherein: thecross-correlation function comprises:C12(d)=Σ_(k=0) ^(m-1) {[S1(tk)− S1]·[S2(tk)− S2]}; and determining thevelocity of signals in the wellbore fluid comprises solving for V, usingthe maximum value of the cross-correlation function and the followingequation:d·Δ·t=(Z ₂ −Z ₁)/V.
 11. The method of claim 9, wherein determining atleast one cross-correlation function between at least the first pressuresensor and the second pressure sensor for downwardly propagating wavescomprises: determining a cross-correlation between the signals from thefirst pressure sensor and the second pressure sensor; determining across-correlation between the signals from the first pressure sensor anda third pressure sensor; and determining a cross-correlation between thesignals from the second pressure sensor and the third pressure sensor.12. The method of claim 1, wherein providing at least a first pressuresensor and a second pressure sensor spaced in a drilling systemcomprises: positioning a wireline device within the drilling system,wherein the wireline device includes the at least a first pressuresensor and a second pressure sensor.
 13. The method of claim 1, whereinproviding a first pressure sensor and a second pressure sensor spaced ina drilling system comprises: positioning a fiber-optic device within thedrilling system, wherein the fiber-optic device includes the at least afirst pressure sensor and a second pressure sensor.
 14. The method ofclaim 1, wherein providing at least a first pressure sensor and a secondpressure sensor spaced in a drilling system comprises: positioning thefirst pressure sensor, the second pressure sensor, and a third pressuresensor within one selected from a drill string, and a casing.
 15. Themethod of claim 1, wherein using an algorithm to separate the downwardlypropagating waves from the upwardly propagating waves comprises usingf-k processing techniques.
 16. The method of claim 15, wherein using f-kprocessing techniques comprises applying a fourier transform of signalsfrom at least the first pressure sensor and the second pressure sensorfrom spatial and temporal dimensions into data in frequency andwavenumber dimensions.
 17. The method of claim 16, wherein the data infrequency and wavenumber dimensions are multiplied by factors to producea reduced data set where at least one of an amplitude and a frequency ofdownwardly propagating waves associated with noise is minimized.
 18. Themethod of claim 17, further comprising applying an inverse fouriertransform on the reduced data set to transform the data set back to thespatial and temporal dimensions.
 19. The method of claim 1, wherein thedownwardly propagating waves comprise noise and the upwardly propagatingwaves comprise a data signal.
 20. The method of claim 1, wherein thedownwardly propagating waves comprise a data signal and the upwardlypropagating signal comprises one of noise and a second data signal.